The invention relates to the treatment of natural gas and other gas streams containing carbon dioxide and methane. More particularly, the invention relates to the use of gas separation membranes to remove excess carbon dioxide from the gas.
Natural gas is the most important fuel gas in the United States and provides more than one-fifth of all the primary energy used in the United States. Natural gas is also used extensively as a basic raw material in the petrochemical and other chemical process industries. The composition of natural gas varies widely from field to field. For example, a raw gas stream may contain as much as 95% methane, with only minor amounts of other hydrocarbons, nitrogen, carbon dioxide, hydrogen sulfide or water vapor. On the other hand, streams with large proportions of one or more of these contaminants are common. For example, gas that is extracted as a result of miscible flood enhanced oil recovery may be very rich in carbon dioxide, as well as being saturated with C3+ hydrocarbons.
Overall, about 10% of gas exceeds the typical gas pipeline specification for carbon dioxide of no more than 2%.
Before such gas can be sent to the supply pipeline, the carbon dioxide content must be reduced. Various techniques for acid gas removal, including absorption into an amine solution, cryogenic separation and membrane separation, have been used in the industry. Each has its own advantages and disadvantages.
If membrane separation is used, cellulose acetate membranes, which can provide a carbon dioxide/methane selectivity of about 10-20 in gas mixtures at pressure, have been the membranes of choice, and about 100 plants using cellulose acetate membranes are believed to have been installed around the world.
It would be desirable in many more cases to use membrane separation, because membrane systems are relatively simple, have few moving parts, can operate under moderate temperature and pressure conditions and, unlike amine scrubbing, do not require a regeneration cycle. Also, the wellhead gas pressure may be high enough to provide the total driving force for transmembrane permeation. However, cellulose acetate and other polymeric membranes are not without problems.
Natural gas often contains substantial amounts of water, either as entrained liquid, or in vapor form, which may lead to condensation within the membrane modules. The gas separation properties of cellulose acetate membranes are destroyed by contact with liquid water. Therefore, care must be taken to remove all entrained liquid water upstream of the membrane separation steps and to lower the water vapor dew point comfortably below the lowest temperature that the gas under treatment is likely to encounter.
Likewise, many membranes are irreparably damaged by liquid hydrocarbons, and similar precautions must be taken to avoid the risk of condensation of C3+ hydrocarbons on the membranes at any time. The presence of more than modest ppm levels of hydrogen sulfide, especially in conjunction with water and heavy hydrocarbons, is also potentially damaging.
Furthermore, carbon dioxide readily sorbs into and interacts strongly with many polymers, and in the case of gas mixtures such as carbon dioxide/methane with other components, the carbon dioxide tends to have a swelling or plasticizing effect, thereby adversely changing the membrane permeation characteristics. Although some membrane materials, such as polyimides, exhibit a high ideal selectivity for carbon dioxide over methane when measured with pure gases at modest pressures in the laboratory, the selectivity obtained under mixed gas, high-pressure conditions is much lower. This means it is often very difficult under field conditions to meet target specifications for carbon dioxide content without resorting to impractically large amounts of membrane area and/or unacceptably complicated processing schemes.
These issues are discussed in more detail in U.S. Pat. No. 5,407,466, columns 2-6, which patent is incorporated herein by reference.
Thus, although membranes have been, and are, used to remove carbon dioxide from natural gas, there are many situations where the composition of the gas, the size of the stream to be processed, or the site geography render a membrane-based process technically or economically unrealistic.
That membranes can separate C3+ hydrocarbons from gas mixtures, such as natural gas, is known, for example from U.S. Pat. Nos. 4,857,078, 5,281,255 and 5,501,722. It has also been recognized that condensation and membrane separation maybe combined, as is shown, for example, in U.S. Pat. Nos. 5,089,033; 5,199,962; 5,205,843 and 5,374,300.
In spite of the above knowledge and practices, technology that can process gas containing excess quantities of carbon dioxide, C3+ hydrocarbons and water in a cost-effective manner is still needed. The challenge of treating gas that contains relatively large amounts of carbon dioxide, such as more than about 8% or 10%, for example, is particularly difficult.
The invention is a process and apparatus for separating carbon dioxide from gas, especially natural gas, that also contains C3+ hydrocarbons. The invention uses two or three membrane separation steps, optionally in conjunction with cooling/condensation/phase separation under pressure, to yield a lighter, sweeter product natural gas stream, and/or a carbon dioxide stream of reinjection quality and/or a natural gas liquids (NGL) stream.
In a basic embodiment, the process of the invention includes the following steps for treating a gas stream:
(a) providing a first membrane having a first feed side and a first permeate side and being selective for C3+ hydrocarbons over methane;
(b) passing the gas stream, under conditions in which the gas stream has a carbon dioxide partial pressure of at least about 30 psia and a C3+ hydrocarbons combined partial pressure of at least about 30 psia, to the first membrane on the first feed side;
(c) withdrawing from the first feed side a first residue stream depleted in C3+ hydrocarbons compared with the gas stream;
(d) withdrawing from the first permeate side a first permeate stream enriched in C3+ hydrocarbons compared with the gas stream;
(e) providing a second membrane having a second feed side and a second permeate side and being selective for carbon dioxide over methane;
(f) passing the first residue stream to the second membrane and across the second feed side;
(g) withdrawing from the second feed side a second residue stream depleted in carbon dioxide compared with the first residue stream;
(h) withdrawing from the second permeate side a second permeate stream enriched in carbon dioxide compared with the first residue stream;
(i) providing a third membrane having a third feed side and a third permeate side and being selective for carbon dioxide over methane;
(j) passing the second permeate stream to the third membrane and across the third feed side;
(k) withdrawing from the third feed side a third residue stream depleted in carbon dioxide compared with the second permeate stream;
(l) withdrawing from the third permeate side a third permeate stream enriched in carbon dioxide compared with the second permeate stream;
(m) optionally recirculating at least a portion of the third residue stream for further treatment within the process;
(n) optionally recirculating at least a portion of the first permeate stream to step (b).
Such an embodiment can be used if no removal of C3+ hydrocarbons prior to treatment in the membrane separation units is required. The first permeate stream will be enriched in C3+ hydrocarbons compared with the feed stream, and may be treated, for example by compression/cooling/phase separation, to recover condensed hydrocarbons as an NGL stream.
A typical embodiment in which compression, cooling and phase separation steps are used upstream of the membrane separation units includes the following steps:
(a) compressing the gas stream;
(b) cooling the gas stream, thereby inducing condensation of a portion of C+ hydrocarbons;
(c) separating the gas stream into a C3+ hydrocarbon liquid phase and an uncondensed gas stream;
(d) providing a first membrane having a first feed side and a first permeate side and being selective for C3+ hydrocarbons over methane;
(e) passing the uncondensed gas stream, under conditions in which the uncondensed gas stream has a carbon dioxide partial pressure of at least about 30 psia and a C3+ hydrocarbons combined partial pressure of at least about 30 psia, to the first membrane on the first feed side;
(f) withdrawing from the first feed side a first residue stream depleted in C3+ hydrocarbons compared with the uncondensed gas stream;
(g) withdrawing from the first permeate side a first permeate stream enriched in C3+ hydrocarbons compared with the uncondensed gas stream;
(h) providing a second membrane having a second feed side and a second permeate side and being selective for carbon dioxide over methane;
(i) passing the first residue stream to the second membrane and across the second feed side;
(j) withdrawing from the second feed side a second residue stream depleted in carbon dioxide compared with the first residue stream;
(k) withdrawing from the second permeate side a second permeate stream enriched in carbon dioxide compared with the first residue stream;
(l) providing a third membrane having a third feed side and a third permeate side and being selective for carbon dioxide over methane;
(m) passing the second permeate stream to the third membrane and across the third feed side;
(n) withdrawing from the third feed side a third residue stream depleted in carbon dioxide compared with the second permeate stream;
(o) withdrawing from the third permeate side a third permeate stream enriched in carbon dioxide compared with the second permeate stream;
(p) optionally recirculating at least a portion of the third residue stream for further treatment within the process;
(q) optionally recirculating at least a portion of the first permeate stream to step (a).
Compression step (a) both facilitates condensation of hydrocarbons in step (b) and raises the gas stream to a suitable pressure for treatment in the subsequent membrane separation steps.
Cooling step (b) is typically carried out simply by air cooling. In general, it is not necessary to cool the gas stream to very low temperatures to knock out C3+ hydrocarbons, because the hydrocarbon dew point is controlled by the subsequent membrane separation step.
Steps (a) and (b) give rise to a discrete liquid phase that includes the heavier hydrocarbons that have condensed under the prevailing pressure and temperature conditions, as well as dissolved hydrogen sulfide, if present, carbon dioxide, water and small amounts of dissolved light hydrocarbons. The condensed C3+ hydrocarbons liquid is removed by means of a phase separator or the like in step (c).
In some situations, the condensed C3+ hydrocarbons liquid has value as a natural gas liquids (NGL) product. If it is not required as a separate product of the process, the C3+ hydrocarbons condensate stream can be remixed in whole or part with other liquid or gas streams available in the gas processing plant.
Other intermediate embodiments including any subset of steps (a), (b) and (c) may also be used. For example, if the raw feed stream is already a two-phase mixture containing entrained hydrocarbon liquids as mist or droplets, step (c) may be used, but steps (a) and (b) may not be required. As another example, if the gas is already at high pressure, step (a) may be omitted and steps (b) and (c) used to condense and knock out C3+ hydrocarbons.
After the optional compression/cooling/phase separation steps, the uncondensed gas is then treated in three membrane separation steps, as in the basic embodiment.
The first membrane separation step uses a membrane that is selective in favor of C3+ hydrocarbons over methane. Any membrane that provides such properties may be used. Rubbery polymeric membranes are preferred, and silicone rubber membranes are especially preferred, although other membranes are known that meet this criterion, including xe2x80x9csuper-glassyxe2x80x9d polymer membranes and inorganic membranes, such as microporous carbon or ceramic membranes.
The membranes for this separation step may take any convenient form known in the art. If rubbery membranes are used, the preferred form is a composite membrane including a microporous support layer for mechanical strength and a thin rubbery coating layer that is responsible for the separation properties.
A benefit of using silicone rubber or similar rubbery membranes is that they are able to operate satisfactorily in the presence of combinations of water, carbon dioxide and C3+ hydrocarbons. Therefore, the partial pressures of both the hydrocarbons and the water in the feed to the first membrane separation step may be high, even close to, at or beyond the saturation vapor pressures of those components. For example, the C3+ hydrocarbons combined partial pressure may be at least about 30 psia, 50 psia, 75 psia or more.
Similarly, the carbon dioxide partial pressure may be relatively high, such as at least about 30 psia, 50 psia, 100 psia, 150 psia, 200 psia or above.
The feed gas may be reheated if desired before passing into the first membrane separation step, as discussed in more detail below.
A driving force for transmembrane permeation is provided by the pressure difference between the feed and permeate sides, which can be provided by compressing the feed stream (if it is not already at sufficiently high pressure), drawing a vacuum on the permeate side, or a combination of both.
C3+ hydrocarbons, water vapor and some carbon dioxide simply pass into the permeate stream as preferentially permeating components, even if the membrane separation is performed at conditions close to, at or even beyond the water or hydrocarbon dew points.
This first permeate stream, enriched in C3+ hydrocarbons, is usually, but not necessarily, recirculated to the front of the process where it may reenter the upstream compression/cooling steps, if used, to increase C3+ hydrocarbon removal and recovery.
By preferentially removing heavier hydrocarbon components, the first membrane separation step reduces the hydrocarbon dew point of the gas, preferably by at least about 5xc2x0 C. and most preferably by at least about 10xc2x0 C. This dew point reduction helps to protect the membranes used in the subsequent membrane separation steps from damage by heavier hydrocarbons.
Since the heavier hydrocarbons are removed, this step may also be used to control the Btu value of the final product gas.
The residue stream from this step is lighter, drier and sweeter than the feed. Owing to cooling brought about by Joule-Thomson expansion across the membrane to the permeate side, the residue stream is also colder than the feed stream, and often substantially colder, such as 5xc2x0 C. colder, 10xc2x0 C. colder or more.
The residue stream passes as feed to the second membrane separation step. If a further relatively large feed-to-residue drop in temperature is anticipated in the second membrane step, it may be desirable to heat the residue stream before passing it into the second membrane separation step to ensure that the gas on the feed side remains above the dew point throughout the step.
However, as explained in more detail below, less heating is required than would be the case in a prior art membrane separation process using only cellulose acetate membranes, for example.
This is beneficial, as it allows the carbon dioxide separation steps to operate at a comparatively cool temperature, thereby enhancing the carbon dioxide/methane selectivity. The second membrane separation step may often be operated at a temperature no higher than about 60xc2x0 C., 50xc2x0 C., 40xc2x0 C. or even lower, for example.
The second membrane separation step is equipped with membranes selective in favor of carbon dioxide over methane and other hydrocarbons. The membrane material used in this step is preferably a glassy polymer with good carbon dioxide/methane selectivity under conditions of high carbon dioxide partial pressure. Representative membrane materials that can be used for this step include polyimides, fluorinated dioxoles and dioxolanes, and cellulose acetate.
The membranes used for this second membrane separation step may again take any convenient form known in the art. Preferably the membranes are asymmetric membranes, having a thin skin that is responsible for the separation properties and an underlying integral microporous support layer, or composite membranes.
The second membrane separation step divides the gas stream into a carbon-dioxide-enriched permeate stream and a carbon-dioxide-depleted, methane-rich residue stream. One potentially valuable product of the process is the methane-rich second residue stream. Preferably, this stream meets target specifications to be useful as a product stream, such as an engine fuel stream, without needing substantial additional processing.
Preferably, this stream contains no more than about 10% carbon dioxide and more preferably no more than about 5% carbon dioxide. Most preferably, this gas stream meets pipeline specification of no more than about 2% carbon dioxide.
This product gas is provided from the high-pressure side of the membrane separation system, and is withdrawn and sent to the gas pipeline, for further purification, or elsewhere as desired.
If the raw gas stream has a relatively high carbon dioxide content, such as 8%, 10%, 15% or more, and it is desired to reduce the concentration of carbon dioxide in the second residue stream to no more than 2%, a relatively high stage-cut is needed in the second membrane separation step. Thus, in this case, besides being enriched in carbon dioxide, typically to at least about 40% or 45% carbon dioxide, the second permeate stream also contains substantial quantities of methane that have permeated with the carbon dioxide.
To achieve better overall methane recovery, this second permeate stream, after optional recompression, is passed as feed to the third membrane separation step. This step also contains membranes selective in favor of carbon dioxide over methane and other hydrocarbons. The membranes may, but need not be, the same as those used in the second membrane separation step. This step produces a third residue stream that is enriched in methane and depleted in carbon dioxide compared with the second permeate stream.
This third residue stream is preferably, but not necessarily, recirculated to the feed side of the second membrane separation step. When compared with the first residue stream, which is also treated in the second membrane separation step, the total hydrocarbon content of the third residue stream is made up of proportionately more methane and less C3+ hydrocarbon, because the heavier components are preferentially retained on the feed side of the second membrane separation step.
Thus, besides increasing methane recovery, another result of recirculating the third residue stream is to lower the hydrocarbon dew point of the feed to the second membrane separation step.
The third permeate stream is the most carbon-dioxide rich stream of the process, and typically may contain at least about 40%, 45%, 50% or more carbon dioxide. If the process is primarily used to sweeten a raw natural gas stream to make a pipeline grade natural gas product, this stream may simply be a waste stream, and may be flared or otherwise disposed of as desired.
On the other hand, if the process is directed at recovering carbon dioxide from a gas stream generated by miscible flood enhanced oil recovery, the recovered carbon dioxide stream may be the principal product of the process. In this case, the carbon dioxide content of the stream is typically above 70%, such as at least about 75%, 80%, 90%, 95% or higher.
Heat integration within the process may be practiced as desired. In particular, the cold permeate or residue streams from the first membrane separation step may be used to cool the raw incoming gas if a lower temperature is needed in the cooling/condensation step.
Depending on the pressure at which the raw gas can be provided to the process, and the operating parameters of the process itself, one or two compression steps will usually be needed: (i) to recompress the second permeate stream for treatment in the third membrane separation step, and/or (ii) to raise the pressure of the incoming raw gas stream. It is often possible to divert a portion of the second permeate stream, or another process stream of suitable composition, for use as engine fuel to power such compressors.
Depending on the incoming raw gas composition, it may be possible to reach target specification for composition of the product stream without using the third membrane separation step.
In this aspect, a basic embodiment of the process of the invention includes the following steps for treating the raw gas stream:
(a) providing a first membrane having a first feed side and a first permeate side and being selective for C3+ hydrocarbons over methane;
(b) passing the gas stream, under conditions in which the gas stream has a carbon dioxide partial pressure of at least about 200 psia and a C3+ hydrocarbons combined partial pressure of at least about 30 psia, to the first membrane on the first feed side;
(c) withdrawing from the first feed side a first residue stream depleted in C3+ hydrocarbons compared with the gas stream;
(d) withdrawing from the first permeate side a first permeate stream enriched in C3+ hydrocarbons compared with the gas stream;
(e) providing a second membrane having a second feed side and a second permeate side and being selective for carbon dioxide over methane;
(f) passing the first residue stream to the second membrane and across the second feed side;
(g) withdrawing from the second feed side a second residue stream depleted in carbon dioxide compared with the first residue stream;
(h) withdrawing from the second permeate side a second permeate stream enriched in carbon dioxide compared with the first residue stream.
(i) optionally recirculating at least a portion of the first permeate stream to step (b).
In this aspect, a typical embodiment in which compression, cooling and phase separation steps are used upstream of the membrane separation units includes the following steps:
(a) compressing the gas stream;
(b) cooling the gas stream, thereby inducing condensation of a portion of C3+ hydrocarbons;
(c) separating the gas stream into a C3+ hydrocarbon liquid phase and an uncondensed gas stream;
(d) providing a first membrane having a first feed side and a first permeate side and being selective for C3+ hydrocarbons over methane;
(e) passing the uncondensed gas stream, under conditions in which the uncondensed gas stream has a carbon dioxide partial pressure of at least about 200 psia and a C3+ hydrocarbons combined partial pressure of at least about 30 psia, to the first membrane on the first feed side;
(f) withdrawing from the first feed side a first residue stream depleted in C3+ hydrocarbons compared with the uncondensed gas stream;
(g) withdrawing from the first permeate side a first permeate stream enriched in C3+ hydrocarbons compared with the uncondensed gas stream;
(h) providing a second membrane having a second feed side and a second permeate side and being selective for carbon dioxide over methane;
(i) passing the first residue stream to the second membrane and across the second feed side;
(j) withdrawing from the second feed side a second residue stream depleted in carbon dioxide compared with the first residue stream;
(k) withdrawing from the second permeate side a second permeate stream enriched in carbon dioxide compared with the first residue stream;
(l) optionally recirculating at least a portion of the first permeate stream to step (b).
As with the embodiment comprising three membrane separation steps, steps (a), (b) and (c) are all optional and may be used independently of each other or in any combination.
Embodiments comprising two membrane separation steps maybe useful, for example, when the raw gas is already very rich in carbon dioxide, such as containing 50% or more carbon dioxide, and the desired product is the second permeate stream, which may be enriched to a carbon dioxide content of at least about 60%, 70% or more.
In another aspect, the invention is a system or apparatus for carrying out removal of carbon dioxide from natural gas or other hydrocarbon-containing gas. In this aspect, the invention includes the following elements:
(a) a first compressor having a compressor inlet line and a compressor outlet line;
(b) cooling means positioned in the compressor outlet line for cooling compressed gas passing through the compressor outlet line;
(c) a phase separator positioned in the compressor outlet line such that condensed liquids can be removed from compressed, cooled gas;
(d) a first membrane separation unit containing a first membrane selective for C3+ hydrocarbons over methane, and having a first feed side and a first permeate side, the first membrane separation unit being connected to the phase separator such that gas can flow from the phase separator to and across the first feed side of the first membrane;
(e) a recirculation line connecting the first permeate side and the compressor inlet line;
(f) a second membrane separation unit containing a second membrane selective for carbon dioxide over methane, and having a second feed side and a second permeate side, the second membrane separation unit being connected to the first membrane separation unit such that gas can flow from the first feed side to and across the second feed side;
(g) a third membrane separation unit containing a third membrane selective for carbon dioxide over methane, and having a third feed side and a third permeate side, the third membrane separation unit being connected to the second membrane separation unit such that gas can flow from the second permeate side to and across the third feed side, and from the third feed side to and across the second feed side;
(h) a second compressor connected between the second and third membrane separation units such that gas leaving the second permeate side can be compressed before flowing to the third feed side.